Not applicable.
The modern history of the production of fluid hydrocarbons begins in the latter half of the 19th century with the vision of a few promoters seeking to exploit xe2x80x9crock oilxe2x80x9d. Rock oil, as opposed to animal fats or vegetable oil, was observed seeping into salt wells in the isolated wooded hills of western Pennsylvania. From that modest birth, by the 20th century, petroleum production had become a predominate world industry. As that industry has developed, the underlying technology has advanced concomitantly.
While wells within some geologic regions are capable of producing under naturally induced reservoir pressures, more commonly encountered are well facilities which employ some form of artificial lift-based production procedure. The purpose of artificial lift is to maintain a reduced producing bottom hole pressure (BHP) such that the involved geologic formation can give up desired reservoir fluids. If a predetermined drawdown pressure can be maintained, a well will produce desired fluids notwithstanding the form of lift involved. In general, lift systems may involve sucker rod pumping (beam pumping), gas lift, electrical submersible pumping, hydraulic pumping, jet pumping, plunger lift, as well as other modalities. See generally:
Brown et al., xe2x80x9cThe Technology of Artificial Lift Methods, Vol. 2a, Pennwell Publishing Co., Tulsa, Okla. (1980).
One widely employed approach to hydrocarbon fluid production is a non-pumping gas lifting one wherein a cyclical opening and closing of a well is carried out. Generally referred to as xe2x80x9cintermittingxe2x80x9d, this cyclical process provides alternating on-cycles and off-cycles which are established by the operation of a gas driven motor valve which, when utilized in conjunction with gas production, functions to produce gas to a sales line and is referred to as a xe2x80x9csales valvexe2x80x9d.
The timing involved in intermitting a well has long been considered critical, the timing of on-cycles and off-cycles having been a taxing endeavor to well production. In this regard, early endeavors called upon the technician to monitor many well parameters including tubing pressure, casing pressure, sales line pressure and many other heuristic details. A failure of the intermitting process would typically result in an excessive quantity of liquids being accumulated within the tubing string of the well, a condition generally referred to as xe2x80x9cloading upxe2x80x9d of the well. This condition represents a failure which may be quite expensive to correct.
For a substantial period of time, control over the cyclical production of wells was based simply upon a crude, clock-operated device. This device required hand winding and thus well location visitation by technicians on a quite frequent basis. Inasmuch as those locations are, for the most part, difficult to access the earlier spring-wound controllers were a source of much frustration to industry. That frustration commenced to end with the introduction to the industry of a long life battery operated controller by W. L. Norwood about 1978. Described in U.S. Pat. No. 4,150,721, entitled Gas Well Controller System, issued Apr. 24, 1979, this seminal and pioneer electric controller provided for long term, battery operated control over wells and served to simplify the control adjustment procedure required of well technicians. Of particular importance, the controller was designed to respond to system parameters to override the cycle timing to accommodate conditions wherein such timing should be overridden and subsequently reinitiated on an automatic basis. Sold under the trademark xe2x80x9cDigitrolxe2x80x9d, the controller, incorporated in a classic green metal box, is still seen to be performing on wells and has had a profound impact upon well production.
At about the time of the introduction of the Norwood controller, some leading petroleum engineers were promoting a plunger method of artificial lift wherein an untethered piston which is referred to as a xe2x80x9cplungerxe2x80x9d is slidably installed within the tubing string of the well and is permitted to travel the entire length of that tubing string in conjunction with the on-cycles and off-cycles of the well. While promising many advantageous aspects of well production, the plunger lift approach to artificial lift was hindered by a lack of appropriate control. The Norwood controller, being able to respond to plunger arrival at a wellhead essentially permitted the creation of a successful plunger lift based industry.
In 1980, W. L. Norwood introduced the first practical microprocessor driven controller to the industry. This instrument, marketed under the trademark xe2x80x9cLiquiliftxe2x80x9d, gave well technicians a substantially expanded capability and flexibility for well control, providing for response to a substantial number of well parameters, as well as for the development of delay techniques to accommodate for temporary system excursions and the like. The initial version of the Liquilift device is described in U.S. Pat. No. 4,352,376 by Norwood, entitled xe2x80x9cController for Well Installationsxe2x80x9d, issued Oct. 5, 1982.
In 1991, Rogers, Jr., introduced a control technique for plunger lift wells which optimized production through the evaluation of the speed at which the plunger arrives at the wellhead. Deviations from this optimum speed are detected and afterflow times as well as off cycle intervals were then varied to, in effect, xe2x80x9ctunexe2x80x9d the well toward optimum plunger speed performance. Where excessive low plunger speed was encountered, a second motor valve referred to as a tank or vent valve was opened to vent the well, in effect, to atmospheric pressure. The production technique had a profound impact upon the industry, improving gas production performance, for example, from about 50% to as high as 150%.
The gas lift approach to artificial lift is a method of lifting fluid wherein relatively high pressure gas is used as the lifting medium in a mechanical form of process. In general, gas lift methodology may involve a continuous flow approach or may employ an intermittent lift technique. In continuous flow, a continuous volume of high-pressure gas is introduced to the well to aerate or lighten the fluid column until reduction of the bottom hole pressure will allow sufficient differential across the sand face. To accomplish this, a flow valve is used that will permit the deepest possible one point injection of available gas lift pressure in conjunction with a valve that will act as a changing or variable orifice to regulate gas injected at the surface. This approach is used in wells with a high productivity index (PI) and a reasonably high bottom hole pressure (BHP) relative to well depth.
An intermittent flow gas lift approach involves expansion of a high pressure gas ascending to a low pressure outlet. This high pressure gas is called upon to drive a slug of liquid from the well. Typically, the intermittent lift is accomplished through the utilization of a multi-point injection of gas through more than one gas lift valve. For such an approach, the installation is designed so that the lowest gas lift valve is opened just as the bottom of the liquid slug passes each such valve. Gas lift approaches, however are inefficient in that there is about a 7% fallback of liquids from the slug for each 1,000 feet of well depth. In this regard, for example, for a well of 10,000 feet depth, 70% of the slug of liquid may be left in the well for each intermitting cycle. Accordingly, much of the energy employed in injecting compressed gas into the well is wasted. Gas lift installations also are hindered by a somewhat ineffective removal of solids such as sand or scale which may accumulate in the well. By contrast, plunger lift procedures will drive such materials from the well by virtue of the necessarily involved efficient plunger to liquid interface. Intermitting approaches to artificial lift procedures also may adversely effect the geologic zone of production involved. In this regard, the well is closed in for an off-cycle interval during which pressure builds against that zone. The effect is more pronounced where injected lifting gas is pressurized against that zone.
Intermitting gas lift installations also will pose problems at the gathering system associated with a well. Such gathering systems are composed of all the lines, separators and low-pressure volume chamber that supply gas to the suction side of the gas lift compressor. If the gas lift cycles are far apart in time, the compressor will be starved of gas between cycles and excessive make-up gas will be required. One solution described for this problem suggests the use of low-pressure volume chamber which save gas for the compressor. Where continuous flow wells are present the problem is substantially ameliorated.
Some gas producing wells are characterized in exhibiting a very high production index (PI). As a consequence, the length of casing perforation admitting production zone gas, referred to as the perforation or pay interval, can be quite extensive, for example, up to about 1,500 feet. Producing these wells with plunger lift procedures is problematic since the tubing string cannot extend to the well bottom which will be located below the perforation zone and determining an end position for inflow with respect to the perforation interval is difficult. The reservoir characteristic associated with these wells also may evoke a low bottom hole pressure (BHP) condition such that significant accumulation of liquids are encountered. A resultant liquid pressure head militates against effective gas production and thus, its removal is called for.
A technique of injection gas lift referred to as a xe2x80x9cchamber installationxe2x80x9d often is elected for these low BHP, high PI characterized wells.
Often a chamber installation increases the total oil production. A chamber is an ideal installation to run in a low BHP, high PI well. This well will produce fairly high fluid volumes if a high drawdown is created on the sand face. A chamber allows the lowest flowing BHP possible to obtain by gas lift. The chamber uses the casing volume to store fluids. Brown et al., (supra), pp 125-126.
These chambers may assume a variety of configurations, but function to use the casing volume to store fluids and lower the liquid pressure head. However, as noted above, gas injection lift procedures for these typically deep wells are inefficient due to significant fallback or slippage of the liquid being driven from the well. Where chamber lift is employed fallback falls to 5% per 1000 feet, only a slight improvement, however inefficiency remains significant. See Brown et al., (supra) p 324.
In the same well installations, the liquids are removed with down hole rod string driven pumps. However, in the gassy environment of the wells such positive displacement devices tend to ingest gas and commence to become what is referred to as being xe2x80x9cgas lockedxe2x80x9d. As a consequence, the pumps become quite inefficient and are subject to failure. Rod string pump actuation, in and of itself, is difficult in deep wells due to material strain. Further, the pumps must be shut-in periodically to permit liquid buildup such that they can be loaded with liquid to commence pumping. Of course, the pumps are not immune from damage due to solid accumulations at the down hole location.
The present invention is addressed to methods for operating a well installation wherein improved well deliquidfication is achieved with chamber configurations which are enhanced with the more positive liquid displacement of plunger lift. Gas production is provided from the larger cross-sectional annulus as defined between the well casing and tubing string to advantageously lower gas flow friction and provide for enhanced production intervals. In one embodiment such production interval is continuous, without interruption.
Where gas under pressure is supplied to the well installation, an injection passageway to the chamber is provided in isolation from the formation zone to carry out a U-tube drive to the plunger, thus avoiding an otherwise deleterious pressurization of the zone.
Key benefits of this method are as follows:
1) Achieve Continuous Flow
Gas and liquid production is maximized from low bottom hole pressure/high productivity index wells by efficiently removing liquid and producing at the lowest possible bottom hole pressure. This creates the lowest sand/face pressure by producing the formation gas from the primary casing/tubing annulus 24 hours per day.
2) Produce Long Perforated Intervals with Low Bottom Hole Pressure
Utilization of a chamber configuration allows long perforated pay intervals to be produced at minimum pressure ensuring fluid storage with a minimum amount of head pressure. Injection gas is isolated from the formation by creating a closed chamber system. There is a reduction of the pressure build-up time normally required by adding injection pressure source gas from a source of gas under pressure. Artificially creating this pressure improves cycle frequency and accomplishes maximum draw down on the reservoir.
3) Reduce Friction Through Annular Flow
Dynamic gas friction is minimized by producing through the larger conduit defined by the primary annulus as opposed to the smaller production tubing to improve inflow performance. Pressure drawndown is maximized by removing the liquids from the well bore and distributing them across the largest cross-sectional area, (i.e. casing/tubing annulus). The tubing can be set low in the well bore creating maximum draw down of pressure as liquid is removed. Traditional plunger lift requires the tubing to be set higher in the well bore.
4) Reduce Formation and Compression Surge
Compression surge is mitigated by continuous production from the casing/tubing primary annulus. Formation pressure surge is significantly improved by producing the casing/tubing primary annulus 24 hours per day. Reducing the pressure cycle on the formation mitigates sand and solids production. Solids removal is better accomplished by the high frequency of plunger cycles, thus not allowing solids to settle and accumulate in the bottom of the tubing.
5) Total Gas System Management
Requirements for xe2x80x9cmake-upxe2x80x9d gas are minimized by utilizing a semi-closed single well intermittent rotative system. There is a maximization of the use of injection gas when using a gas injection system (i.e. high pressure, clean dry gas). The control theory allows for modification to the injection cycle time based on plunger performance and therefore adjusts the volume of gas injected for the amount of fluid that is being produced. A minimization of gas and liquid production loss is achieved utilizing a concentric tubing concept. Well equipment can be installed and implemented with this concentric tubing concept without having to xe2x80x9ckillxe2x80x9d the well. This technique minimizes the potential of damaging the reservoir and will improve the speed at which the application will be returned to a producing status.
Another feature and object of the invention is to provide a method for operating a well installation having a casing extending within a geologic formation from a wellhead to a bottom region, the casing having a perforation interval extending to an end location at a given depth, the installation including a collection facility and a source of gas under pressure having an injection output, comprising the steps of:
(a) providing a tubing assembly within the casing including a plunger lift tube having a tube outlet at the wellhead and extending to a tubing input located in adjacency with or below the perforation interval end location communicable in fluid passage relationship with formation fluids and having an injection input;
(b) providing an injection passage adjacent the plunger lift tube extending from the injection output at least to the plunger lift tube injection input;
(c) providing a plunger within the plunger lift tube movable between a bottom position located above the injection input and the wellhead;
(d) providing a formation fluid receiving assembly defining a chamber with the injection passage in fluid communication with the tubing assembly, the chamber having a lower disposed check valve assembly with an open orientation admitting formation fluid within the chamber and responsive to injection fluid pressure to define a U-tube function with the injection passage and the tubing assembly;
(e) providing a tubing valve between the tube outlet and the collection facility actuable between an open orientation permitting the flow of fluid to the collection facility and a closed orientation blocking the tube outlet;
(f) providing an injection control assembly actuable between an open condition effecting application of gas under pressure from the pressurized gas output to the injection gas input and a closed condition;
(g) providing a detector at the wellhead having a detector output in response to the arrival of the plunger at the wellhead;
(h) accumulating formation fluid into the chamber by passage thereof through the check valve assembly;
(i) moving fluid from the chamber into the tubing assembly above the plunger;
(j) actuating the injection control assembly to the open condition to apply gas under pressure to the defined U-tube from the injection input, to impart upward movement to the plunger;
(k) actuating the tubing valve to the open orientation;
(l) actuating the injection control assembly to the closed condition in response to the detector output: and
(m) then, actuating the tubing valve into the closed orientation for an off-time interval at least sufficient for the movement of the plunger from the wellhead to the bottom position.
As another feature, the invention provides a method of operating a well installation having a wellhead in fluid transfer relationship with a collection facility and with a well casing extending within a geologic formation and having a perforation interval effectively extending a given depth to an interval depth location, and having a source of gas under pressure with a pressurized gas output, comprising the steps of:
(a) providing an injection passage within the casing, having an injection input coupled with the pressurized gas output extending to an injection outlet and defining a casing production region with the casing;
(b) providing a plunger lift tube at least partially within the injection passage extending from an outlet at the wellhead to a tubing input, the plunger lift tube being communicable in fluid passage relationship with the injection outlet at an injection location;
(c) providing a plunger within the plunger lift tube movable between a bottom position located above the injection location and the wellhead;
(d) providing a formation fluid receiving assembly defining a chamber with the injection passage in fluid communication with the plunger lift tube and the injection outlet, the chamber having a check valve with an open orientation admitting formation fluid within the chamber and responsive to fluid pressure to define a U-tube function with the injection passage and the plunger lift tube;
(e) collecting formation fluid into the plunger lift tube above the plunger bottom position;
(f) communicating the plunger lift tube outlet in fluid transfer relationship with the surface collection facility;
(g) applying injection gas under pressure from the pressurized gas output to the injection input for an injection interval effective to move the plunger to the wellhead and to move formation liquid located above it through the outlet and into the surface collection facility; and
(h) communicating the casing production region in gas transfer relationship with the surface collection facility.
Another feature and object of the invention is to provide a method for operating a well installation have a casing extending within a geologic formation from a wellhead to a bottom region, the installation including a collection facility, and having a source of gas under pressure with a pressurized gas output, comprising the steps of:
(a) providing a tubing assembly within the casing having a plunger lift tube with a tube outlet at the wellhead, extending to a tubing input located to receive formation fluid;
(b) providing an injection passage extending from an injection gas input at the wellhead to an injection outlet;
(c) providing a plunger within the plunger lift tube movable between a bottom position and the wellhead;
(d) providing a formation fluid receiving assembly defining a chamber with the injection passage in fluid communication with the plunger lift tube and the injection outlet, the chamber having a check valve with an open orientation admitting formation fluid within the chamber and responsive to fluid pressure to define a U-tube function with the injection passage and the plunger lift tube;
(e) providing a detector at the wellhead having a detector output in response to the arrival of the plunger at the wellhead;
(f) providing a tubing valve between the tube outlet and the collection facility actuable between an open orientation permitting the flow of fluid to the collection facility and a closed orientation blocking the tube outlet;
(g) providing an injection valve between the pressurized gas outlet and the injection gas input actuable between an open orientation effecting application of gas under pressure to the injection outlet and a closed orientation;
(h) providing an equalizing valve in gas flow communication between the injection gas input and the collection facility, actuable between an open orientation providing the flow communication and a closed orientation blocking the flow communication;
(i) accumulating formation fluid into the chamber through the check valve when the equalizing valve is in the open orientation, the injection valve is in its closed orientation and the check valve is in its open orientation;
(j) moving formation fluid accumulated within the chamber into the plunger lift tube above the plunger;
(k) actuating the equalizing valve into the closed orientation;
(l) actuating the injection valve into the open orientation; and
(m) actuating the tubing valve into the open orientation to effect movement of the plunger toward the wellhead.
As another feature and object, the invention provides a method of operating a well installation having a wellhead in fluid transfer relationship with a collection facility, having a well casing extending from the wellhead within a geologic formation to a lower region, having a tubing assembly extending within the casing from the wellhead to a fluid input at the lower region, the space between the tubing assembly and the casing defining an annulus, comprising the steps of:
(a) blocking fluid flow within the annulus with an annulus seal;
(b) providing an entrance valve assembly positioned to control fluid flow into the tubing assembly;
(c) providing fluid communication between the annulus and the tubing assembly at a communication entrance within the lower region above the entrance valve assembly and the annulus seal;
(d) providing a plunger within the tubing assembly movable between the wellhead and a bottom location above the communication entrance;
(e) providing a tubing valve in fluid flow communication between the tubing assembly at the wellhead and the collection facility, actuable between open and closed orientations;
(f) accumulating formation fluid through the entrance valve assembly into the tubing assembly and the annulus above the annulus seal;
(g) pressurizing the annulus above the seal for a pre-charge interval;
(h) actuating the tubing valve into the open orientation for a purge interval effective to transfer fluid accumulated in the annulus through the communication entrance into the tubing assembly;
(i) actuating the tubing valve into the closed orientation;
(j) pressurizing the annulus;
(k) actuating the tubing valve into the open orientation to commence an on-time driving the plunger toward the wellhead at a plunger speed;
(l) directing fluid above the plunger into the collection facility;
(m) detecting the arrival of the plunger at the wellhead;
(n) communicating the annulus in fluid flow relationship with the collection facility for an afterflow interval in response to the detected arrival of the plunger at the wellhead;
(o) actuating the tubing valve into the closed orientation for an off-time interval permitting the plunger to move toward the bottom location; and
(p) reiterating steps (f) through (o) to define a sequence of well production cycles.
Other objects of the invention will, in part, be obvious and will, in part, appear hereinafter. The invention, accordingly comprises the method possessing the steps which are exemplified in the following detailed disclosure.
For a fuller understanding of the nature and objects of the invention, reference should be had to the following detailed description taken in connection with the accompanying drawings.